Most production and/or injection wells are completed by cementing a string of metal casing in the borehole of the well. The casing and the surrounding cement are perforated adjacent the production and/or injection formation or formations to establish fluid communication between the formation(s) and the casing. One or more strings of metal tubing are then lowered into the casing and their lower ends are positioned adjacent the respective formations to be produced or injected. Fluids are then produced or injected through the tubing strings or, in some instances, through the annulus between the casing and the tubing. If the formation pressure is insufficient to cause the formation fluids (e.g. oil, water, etc.) to flow to the surface, a downhole pump is routinely hung on the lower end of the tubing and is operated by a string of sucker rods which extend from the surface through the tubing.
Since water is almost always present in the produced or injected fluids, corrosion is major problem in most production and injection wells. As is well known in the art, corrosion can seriously affect the operational life of the tubing strings, casing, and/or the metal sucker rods as the case may be, and if not timely treated, can cause early failure of the corroded elements. In known treatments for corrosion in wells, a slug of an appropriate liquid treating solution, e.g. corrosion inhibitor, is flowed down the tubing string. Due to the properties of the corrosion inhibitor, it adheres to the pipe wall; hopefully to form a relatively uniform layer or thin film on the entire surface of the wall to protect the wall from contact with water or other electrolytes or oxidizing agents that may be present in the fluids normally flowing through the tubing.
To insure that an adequate layer of treating solution will be deposited onto the wall as the slug passes therethrough, a substantially greater amount of corrosion inhibitor is used than is required to form the protective layer. This excess of corrosion inhibitor is not only expensive but more importantly, has been found to cause severe damage to many production and/or injection formations when it flows out the bottom of the tubing and into the formation. The real threat of formation damage severely restricts the use of this corrosion treatment which, in turn, creates a real dilemma since corrosion treatment of the well tubulars can not be ignored.
In the present inventor's co-pending U.S. patent application No. 07/683,164, filed Apr. 10, 1991, a method is set forth wherein an ablative gelatin pig containing a treating solution is passed through a tubular to deposit a protective layer onto the wall of the tubular which is similar to method of the present invention.